German Capacity Shortage Looms: Timera
Germany risks a shortage in capacity over the coming few years as the major legislated reductions in coal, lignite and nuclear capacity take effect. There is not enough firm replacement lined up, according to new analysis by Timera published January 28.
Germany has already closed 12 GW of nuclear capacity, which has been replaced with coal. The remaining 8 GW of nuclear is due to close in 2022, but with coal capacity also closing, the current policy intention is for renewables to plug the gap.
Wind and solar now account for 47% of German capacity and a policy emphasis on renewables means this percentage is set to increase significantly over the new few years: the new targets are 98 GW of solar, 20 GW of offshore wind and 73 GW of onshore wind by 2030. But after taking into account de-rating – the discount reflecting actual availability relative to nameplat – Timera sees a net shortfall of 13 GW by 2022, rising to 20 GW by 2030.
Nuclear and coal have low de-rating factors (almost four fifths of nameplate) while solar is low or non-existent across peak demand and wind generation is unpredictable and so de-rating factors are lower than annual average load-factors, says Timera.
On this basis, from an annual energy produced perspective, the shortfall in nuclear energy alone will not be met by renewables until 2026 at the earliest. Once coal and lignite closures are considered, renewables may still not have made up the total energy deficit by the end of the 2020s.
The economics of investing in new sources of flexible capacity are not clear, given the absence of a capacity market. Historically, German transmission system operators have negotiated bilateral contracts to build ‘reserve’ flex, but this approach looks increasingly inconsistent with European initiatives on state aid.
Wholesale market returns do not support new large-scale CCGTs. High capex, long asset life-span and considerable de-carbonisation risks make CCGTs an inherently risky investment without the support of an additional revenue stream such as capacity payments or combined heat and power income.
Gas engines, which have near-instantaneous ramp-up times but are less efficient in their gas burn, have played a big role in delivering new UK capacity over the last five years: they cost less than CCGTs and engines can benefit from a range of other revenue streams such as balancing, reserve, network charge avoidance. But there are no capacity payments in Germany.
That leaves demand-side response (DSR), batteries and other forms of storage to do the heavy lifting to plug the capacity gap. These technologies are not hampered by decarbonisation risk but additonal policy support is required to deliver them at scale.
In addition to new flexible capacity being required, Germany will also likely see a shortfall developing on an energy basis in the 2023-2025 horizon. This is set to drive significantly higher German gas plant load factors. But it also means higher imports from neighbouring markets.
Germany, however, is not going through an energy transition alone. France is closing its coal fleet by 2022, Belgium is phasing out its nuclear fleet by 2025 and Italy & the Netherlands are closing coal fleets by 2030. Conventional wisdom states that increased interconnection between countries will help balance markets in periods of low or high wind, but Timera's analysis of wind load-factors by country shows that might not be the panacea commonly assumed.
Timera believes that an increase in policy support for flexible capacity is likely to be the solution, meaning low carbon flex such as storage, DSR and hydrogen are likely to be the greatest beneficiaries. But gas CHPs and peakers may also receive more support, particularly to displace coal. EU state aid pressure and the scale of the challenge ahead may even lead Germany to consider implementing a broader capacity market, Timera suggests.